Screening method for friction reducer precipitation

ABSTRACT

A method of preparing a fracturing fluid comprising: preparing or providing an aqueous fluid containing iron ions; screening a plurality of friction reducers against the aqueous fluid wherein the plurality of friction reducers are anionic, cationic, nonionic, amphoteric, or combinations thereof; selecting at least one friction reducer from the plurality of friction reducers based at least in part on the step of screening; and preparing a fracturing fluid including the at least one friction reducer.

CROSS REFERENCE TO RELATED APPLICATIONS

The present Applications claims priority to U.S. Provisional ApplicationNo. 62/902,040 filed Sep. 18, 2019, incorporated in its entirety bereference herein.

BACKGROUND

Hydrocarbon-producing wells are often stimulated by hydraulic fracturingoperations, wherein proppants may be used to hold open or “prop” openfractures created during high-pressure pumping. Once the pumping-inducedpressure is removed, proppants may prop open fractures in the rockformation and thus preclude the fracture from closing. As a result, theamount of formation surface area exposed to the well bore may beincreased, enhancing hydrocarbon recovery rates.

An important component of hydraulic fracturing fluids is a frictionreducing polymer. Pumping rates for hydraulic fracturing operations mayregularly exceed 50 barrels per minute (8 m³/min) or more, which maycause turbulence in conduits such as wellbore tubing, liners, andcasings. Turbulent flow of hydraulic fracturing fluid leads to highhorsepower requirements to maintain pressure and flow rates. Some commonfriction reducing polymers may include long chain water soluble polymerswhich may aid in moderating turbulence by reducing eddy currents withina conduit.

A friction reducer may be selected to be included in a fracturing fluidbased at least in part on chemical properties of water available to mixthe fracturing fluid at a well site. The properties of water such asdissolved species, pH, and temperature may affect the solubility of afriction reducer. A reduction in solubility may result in droplets ofpartially hydrated friction reducer to be present in the fracturingfluid. The droplets of partially hydrated friction reducer may result inless friction reduction as compared to a fluid which contains morehydrated friction reducer. Further, the drops of partially hydratedfriction reducer may plug and foul surface and downhole equipment.Oftentimes water and solubility testing are performed prior to preparinga fracturing fluid to ensure the water source does not exhibitproperties which may hinder the hydration of a friction reducer. Whenhydrolyzed friction reducing polymers contact with multivalent ions suchas Fe ions, Ca ions, or Mg ions in formation brine, the solubility ofthe hydrolyzed friction reducing polymers may be reduced which may forminsoluble precipitates. These precipitates may interfere with thefunctionality of stimulation equipment, effectively reversing at leastsome of the friction reducing capacity of the polymers and/or may causedamage to stimulation equipment. Additionally, these precipitates mayintrude into the pores or openings within a formation resulting indamage to the formation or a reduction in formation conductivity.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of the present disclosure, andshould not be used to limit or define the disclosure.

FIG. 1 is a photograph of an oilfield fluid sample containingprecipitated friction reducer.

FIG. 2 is a schematic view of an example well system utilized forhydraulic fracturing.

FIG. 3 is a schematic view of an example of a wellbore afterintroduction of fracturing fluid.

FIG. 4 is a photograph of a fluid sample containing precipitated anionicfriction reducer.

FIG. 5 is a photograph of filtered precipitated anionic frictionreducer.

FIG. 6 is a photograph of two fluid samples containing cationic andnonionic friction reducer.

FIG. 7 is a photograph of four fluid samples containing anionic frictionreducer and iron removal agent.

DETAILED DESCRIPTION

The present disclosure may relate to preparation of fracturing fluidsand in one or more implementation, to a screening method for frictionreducer precipitation. Friction reducers used in slickwater fracturingjobs may be anionic friction reducing polymer. Such friction reducersmay be damaged by some dissolved species such as iron ions in makeupwater and/or formation brine. The cationic ion species dissolved in thewater may be electrically attracted to and associate with the anionicfriction reducer in solution. This may cause a reduction in solubilityof the friction reducing polymer which may lead to precipitates ofhydrated friction reducing polymers. The precipitation caused bydissolved species may also reduce friction reduction efficiency and maycause formation damage if the precipitates are deposited in theformation. FIG. 1 shows an example of a fluid sample from oil fieldcontaining precipitated friction reducer recovered from a fracturingoperation.

There may be a wide variety and number of friction reducing polymersavailable to be included in a fracturing fluid. Friction reducingpolymers may be polysaccharides or may be polymers synthesized from aplurality of monomers, each of which may yield friction reducers withdisparate properties. Additionally, manufacturing techniques andconditions may further influence the properties of a friction reducingpolymer A screening method is therefore needed to determine if afriction reducer is susceptible to dissolved cationic species such asiron in water, and, if treatment may be needed to mitigate the effectsof dissolved species on friction reducers.

By way of example, suitable friction reducing polymers may include anyof a variety of monomeric units, such as acrylamide, acrylic acid,2-acrylamido-2-methylpropane sulfonic acid, acrylamido tertiary butylsulfonic acid, N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinylacetamide, N-vinyl formamide, itaconic acid, methacrylic acid, acrylicacid esters, methacrylic acid esters, and related salts or esters, andcombinations thereof. One example of a suitable anionic frictionreducing polymer may include a polymer comprising acrylamide and acrylicacid. The acrylamide and acrylic acid may be present in the polymer inany suitable concentration. An example of a suitable polymer maycomprise acrylamide in an amount in the range of from about 5% to about95% and acrylic acid in an amount in the range of from about 5% to about95%. Another example of a suitable polymer may comprise acrylamide in anamount in the range of from about 60% to about 90% by weight and acrylicacid in an amount in the range of from about 10% to about 40% by weight.Another example of a suitable polymer may comprise acrylamide in anamount in the range of from about 80% to about 90% by weight and acrylicacid in an amount in the range of from about 10% to about 20% by weight.Yet another example of a suitable polymer may comprise acrylamide in anamount of about 85% by weight and acrylic acid in an amount of about 15%by weight. As previously mentioned, one or more additional monomers maybe included in the polymer comprising acrylamide and acrylic acid. Byway of example, the additional monomer(s) may be present in the frictionreducing polymers in an amount up to about 20% by weight of the polymer.Suitable friction reducing polymers may be in an acid form or in a saltform. As will be appreciated, a variety of salts may be prepared, forexample, by neutralizing the acid form of the acrylic acid monomer orthe 2-acrylamido-2-methylpropane sulfonic acid monomer. In addition, theacid form of the polymer may be neutralized by ions present in thetreatment fluid.

As discussed above, precipitates may can form when dissolved speciessuch as iron ions in water (either makeup water, formation water, orboth) come into contact with friction reducing polymers. Althoughcations such as calcium ions, magnesium ions, barium ions may alsoassociate with friction reducing polymers, iron ions usually havestronger bonding to the friction reducing polymers. In field locations,the iron concentration in makeup water or formation brine may be lowsingle digit parts per million. However, some water may have ironconcentrations that may reach 20-80 ppm (parts per million), 200-400ppm, or higher.

Water used in oilfield operations may be from various sources includingsurface water such as from lakes, rivers, estuaries, and oceans forexample, as well as ground water from aquifers and water wells. Oneadditional source of water in the oilfield may be produced water such aswater that flows from a hydrocarbon well. Hydrocarbon wells oftenpenetrate subterranean formations that contain a fraction of wateralongside hydrocarbons. As such, fluids that are produced from ahydrocarbon well may contain hydrocarbons as well as a fraction ofwater. The produced fluids may be separated at the surface to generate ahydrocarbon stream and a water stream. The water stream may be furtherutilized to mix treatment fluids for well treatment such as drilling,cementing, stimulation, and enhanced recovery operations. The separatedwater stream may be referred to as produced water. Produced water may beconnate water that was trapped in the interstices of the formation whenthe formation was formed or may be water that was introduced into theformation during any number of wellbore operations such as enhanced oilrecovery, for example.

During preparation of treatment fluids, freshwater may be used as a basefluid with additional “make up” water used to make up the remainingvolume of fluid required for a particular application. Make up water maybe from any source as described above including surface water, groundwater, and produced water, for example. Each of the sources of water mayhave varying levels of species dissolved therein, including thosespecies previously described, which may affect the stability of frictionreducers added to the water. While each of the previously mentionedsource of water may be screened for dissolved species, another source ofwater that is not currently screened is formation brines. Whileformation brines are not typically directly added to a treatment fluidduring preparation of the treatment fluid, once the treatment fluid isintroduced into the formation, the treatment fluid and formation brinesmay contact and mix. Thus, if the water used to prepare a treatmentfluid is screened for dissolved species and the water is deemedacceptable for a particular application, damage by formation brine maystill occur when the treatment fluid is introduced into the subterraneanformation and the dissolved species in the formation brine causeprecipitation of friction reducers. As such, present screening methodsemployed in the oilfield may be inadequate to account for all sources ofdissolved species.

A method of screening for compatibility of a friction reducer and watermay include preparing a laboratory formation fluid, adding a frictionreducing polymer to the laboratory formation fluid, and observing ifprecipitation of the friction reducing polymer occurs. The laboratoryformation fluid may be prepared in a manner such that the concentrationof dissolved species in the laboratory formation fluid may berepresentative of a treatment fluid after introduction of the treatmentfluid into a subterranean formation. As discussed above, a volume oftreatment fluid may be prepared and introduced into a subterraneanformation whereby the treatment fluid may contact and mix with formationfluids such as a formation brine. The resulting fluid mixture offormation brine and treatment fluid may be referred to as a dilutedtreatment fluid and may be representative of a fluid that may beexpected to be found in the subterranean formation after introducing thetreatment fluid into the subterranean formation. While there may existtechniques to directly measure properties of the actual fluids presentin a formation after the treatment fluid is introduced into thesubterranean formation, it may be advantageous to model the dilutedtreatment fluid rather than performing the requisite well interventiontechniques to directly sample the actual formation fluid.

Subterranean formations may contain varying volumes of formation brine.Some formations may contain a relatively large fraction of formationbrine such that a volume of treatment fluid introduced therein may bediluted to a greater extent than a formation that contains a relativelysmaller fraction of formation brine. Additionally, some formations maycontain similar fractions of formation brine but may differ inconcentration of dissolved species within the formation brine. In suchexamples, a diluted treatment fluid formed may have disparateconcentrations of dissolved species depending on the concentration ofdissolved species in formation brine. In general, the fluid content of aformation may be measured and/or estimated using open-hole or cased holelogging techniques as well as seismic logging techniques each of whichmay provide guidance to the fluid volume and dissolved species therein.Thus, a diluted treatment fluid model including the volume andconcentration of dissolved species in the diluted formation fluid may bedeveloped using the volume of formation brine and concentration ofspecies therein and volume of treatment fluid and concentration ofspecies therein. In some examples, a mixing model may be employed tofurther refine the diluted treatment fluid model such that a timedependent dissolved species concentration and/or a location dependentdissolved species concentration in the subterranean formation may beestimated. Thus, the diluted treatment fluid model may be used topredict a concentration of dissolved species in the diluted treatmentfluid.

The above mentioned techniques for developing a diluted treatment fluidmodel may further be used to develop and prepare a laboratory formationfluid. The laboratory formation fluid may be prepared based at least inpart on the diluted treatment fluid model. For example, the dilutedtreatment fluid model may indicate that a range of concentrations for adissolved species may be expected to be present in a diluted treatmentfluid. A laboratory formation fluid may be prepared with dissolvedspecies in the ranges indicated by the model. Thereafter, a frictionreducing polymer may be added to the laboratory treatment fluid andobserved. In some examples, the laboratory treatment fluid containingthe friction reducing polymer may be subjected to wellbore conditionssuch as wellbore pressure and temperature to simulate a wellbore. Insome examples, the laboratory formation fluid may be prepared withdissolved species concentration in the range of 50% to about 500% of thediluted treatment fluid model. The laboratory formation fluid may beprepared with dissolved species concentration in the range of about 50%to about 100% of the diluted treatment fluid model, in the range ofabout 100% to about 200% of the diluted treatment fluid model, in therange of about 200% to about 300% of the diluted treatment fluid model,in the range of about 300% to about 400% of the diluted treatment fluidmodel, or in the range of about 400% to about 500% of the dilutedtreatment fluid model. There may be advantages to preparing a laboratorytreatment fluid with a greater connection of dissolved species than adiluted treatment fluid model may predict. Relatively higherconcentrations of dissolved species may react with a friction reducingpolymer more quickly than relatively lower concentrations. For example,dissolved species may not immediately affect the stability andsolubility of friction reducers when the friction reducers are added toa laboratory treatment fluid. The rate of reaction between the dissolvedspecies and friction reducer may be increased by increasing theconcentration of the dissolved species such that the precipitates, ifpresent, may be observed within a reasonable timeframe of hours to days.

Utilizing the above described technique to estimate a concentration ofdissolved species in the actual formation fluid may allow the behaviorof a friction reducing polymer within a subterranean formation to beestimated. A simulated formation fluid may be prepared by providingwater and increasing a concentration of cationic species therein until adesired concentration of dissolved cations is achieved. The dissolvedcations ions may be any of those previously mentioned, including, butnot limited to, iron ions, calcium ions, magnesium ions, aluminum ions,barium ions, and combinations thereof. The cations may be provided inany manner such as in a salt form, or may be generated in-situ byreaction, for example. The method may further include preparing alaboratory formation fluid and performing a screening test on aplurality of friction reducing polymers as described above. One or morefriction reducing polymers may be selected based at least in part on theresults of the screening test. A hydraulic fracturing fluid may then beprepared including the selected friction reducing polymer.

A hydraulic fracturing fluid may include an aqueous base fluid, aproppant, and a friction reducing polymer. The aqueous based fluid mayinclude fresh water, produced water, salt water, surface water, or anyother suitable water. The term “salt water” is used herein to meanunsaturated salt solutions and saturated salt solutions including brinesand seawater. The aqueous base fluid may include dissolved species ofsalts and metals that make up the total dissolved solids count for aparticular sample of aqueous base fluid. Examples of dissolved speciesmay include, but are not limited to, lithium, sodium, potassium,beryllium, magnesium, calcium, strontium, iron, zing, manganese,molybdenum, sulfur in the form of hydrogen sulfide, other sulfides, andsulfates, arsenic, barium, boron, chromium, selenium, uranium, fluorine,chlorine, bromine, iodine, and combinations thereof. One of ordinaryskill in the art will understand that the present list of dissolvedspecies is not exhaustive of all possible species dissolved in aparticular sample of water. Furthermore, one of ordinary skill in theart will understand that particular dissolved species may be of concernwith regards to performance of a particular fiction reducing polymerthan other species. The water may be present in any amount by weightsuitable for a particular hydraulic fracturing application. For example,without limitation, the water may be present at a point ranging fromabout 50 wt. % to about 100 wt. % based on a total weight of thehydraulic fracturing fluid. Alternatively, at a point ranging from about50 wt. % to about 60 wt. %, at a point ranging from about 60 wt. % toabout 70 wt. %, at a point ranging from about 70 wt. % to about 80 wt.%, at a point ranging from about 80 wt. % to about 90 wt. %, or at apoint ranging from about 90 wt. % to about 100 wt. %. One of ordinaryskill in the art with the benefit of this disclosure should be able toselect an appropriate weight percent of water for a particular hydraulicfracturing fluid.

The hydraulic fracturing fluid may include a proppant. Proppants mayinclude a collection of solid particles that may be pumped into thesubterranean formation, such that the solid particles hold (or “prop”)open the fractures generated during a hydraulic fracturing treatment.The proppant may include a variety of solid particles, including, butnot limited to, sand, bauxite, ceramic materials, glass materials,polymer materials, polytetrafluoroethylene materials, nut shell pieces,cured resinous particulates including nut shell pieces, seed shellpieces, cured resinous particulates including seed shell pieces, fruitpit pieces, cured resinous particulates including fruit pit pieces,wood, composite particulates, and combinations thereof. Suitablecomposite particulates may include a binder and a filler materialwherein suitable filler materials include silica, alumina, fumed carbon,carbon black, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and combinations thereof. The proppant mayhave any suitable particle size for a particular application such as,without limitation, nano particle size, micron particle size, or anycombinations thereof. As used herein, the term particle size refers to ad50 particle size distribution, wherein the d50 particle sizedistribution is the value of the particle diameter at 50% in thecumulative distribution. The d50 particle size distribution may bemeasured by particle size analyzers such as those manufactured byMalvern Instruments, Worcestershire, United Kingdom. As used herein,nano-size is understood to mean any proppant with a d50 particle sizedistribution of less than 1 micron. For example, a proppant with a d50particle size distribution at point ranging from about 10 nanometers toabout 1 micron. Alternatively, a proppant with a d50 particle sizedistribution at point ranging from about 10 nanometers to about 100nanometers, a proppant with a d50 particle size distribution at pointranging from about 100 nanometers to about 300 nanometers, a proppantwith a d50 particle size distribution at point ranging from about 300nanometers to about 700 nanometers, a proppant with a d50 particle sizedistribution at point ranging from about 700 nanometers to about 1micron, or a proppant with a d50 particle size distribution between anyof the previously recited ranges. As used herein, micron-size isunderstood to mean any proppant with a d50 particle size distribution ata point ranging from about 1 micron to about 1000 microns.Alternatively, a proppant with a d50 particle size distribution at pointranging from about 1 micron to about 100 microns, a proppant with a d50particle size distribution at point ranging from about 100 microns toabout 300 microns, a proppant with a d50 particle size distribution atpoint ranging from about 300 microns to about 700 micron, a proppantwith a d50 particle size distribution at point ranging from about 700microns to about 1000 microns, or a proppant with a d50 particle sizedistribution between any of the previously recited ranges.

Alternatively, proppant particle sizes may be expressed in U.S. meshsizes such as, for example, 20/40 mesh (212 μm-420 μm). Proppantsexpressed in U.S. mesh sizes may include proppants with particle sizesat a point ranging from about 8 mesh to about 140 mesh (106 μm-2.36 mm).Alternatively a point ranging from about 16-30 mesh (600 μm-1180 μm), apoint ranging from about 20-40 mesh (420 μm-840 μm), a point rangingfrom about 30-50 mesh (300 μm-600 μm), a point ranging from about 40-70mesh (212 μm-420 μm), a point ranging from about 70-140 mesh (106 μm-212μm), or alternatively any range there between. The standards andprocedures for measuring a particle size or particle size distributionmay be found in ISO 13503, or, alternatively in API RP 56, API RP 58,API RP 60, or any combinations thereof.

Proppants may include any suitable density. In some examples, proppantsmay have a density at a point ranging from about 1.25 g/cm³ to about 10g/cm³. Proppants may include any shape, including but not limited, tospherical, toroidal, amorphous, planar, cubic, or cylindrical. Proppantsmay further include any roundness and sphericity. Proppant may bepresent in the fracturing fluid in any concentration or loading. Withoutlimitation, the proppant may be present a point ranging from about 0.1pounds per gallon (“lb/gal”) (12 kg/m³) to about 14 lb/gal (1677 kg/m³).Alternatively, a point ranging from about 0.1 lb/gal (12 kg/m³) to about1 lb/gal (119.8 kg/m³), a point ranging from about 1 lb/gal (119.8kg/m³) to about 3 lb/gal (359.4 kg/m³), a point ranging from about 3lb/gal (359.4 kg/m³) to about 6 lb/gal (718.8 kg/m³), a point rangingfrom about 6 lb/gal (718.8 kg/m³) to about 9 lb/gal (1078.2 kg/m³), apoint ranging from about 9 lb/gal (1078.2 kg/m³) to about 12 lb/gal(1437.6 kg/m³), a point ranging from about 12 lb/gal (1437.6 kg/m³) toabout 14 lb/gal (1677.2 kg/m³), or alternatively, any rangetherebetween.

Friction reducing polymers may be included in the hydraulic fracturingfluid, for example, to form a slickwater fluid, for example. Thefriction reducing polymer may be a polysaccharide or a syntheticpolymer. Additionally, for example, the friction reducing polymer may bean anionic polymer or a cationic polymer or a nonionic polymer or anamphoteric polymer. By way of example, suitable synthetic polymers mayinclude any of a variety of monomeric units, including acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, acrylamidotertiary butyl sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonicacid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylicacid, acrylic acid esters, methacrylic acid esters and combinationsthereof. Suitable friction reducing polymers may be in an acid form orin a salt form. As will be appreciated by one of ordinary skill in theart, a variety of salts may be prepared, for example, by neutralizingthe acid form of the acrylic acid monomer or the2-acrylamido-2-methylpropane sulfonic acid monomer. In addition, theacid form of the polymer may be neutralized by ions present in thefracturing fluid. The term “polymer” in the context of a frictionreducing polymer, may be intended to refer to the acid form of thefriction reducing polymer, as well as its various salts.

The friction reducing polymer may be included in the hydraulicfracturing fluid in the form of a liquid additive, for example, anamount ranging from about 0.1 gallons of the friction reducing polymerper thousand gallons of the fracturing fluid (“GPT”) to about 4 GPT ormore. Alternatively, an amount ranging from about 0.1 GPT to about 0.5GPT, an amount ranging from about 0.5 GPT to about 0.7 GPT, an amountranging from about 0.7 GPT to about 1 GPT, an amount ranging from about1 GPT to about 1.3 GPT, an amount ranging from about 1.3 GPT to about1.6 GPT, an amount ranging from about 1.6 GPT to about 2 GPT, an amountranging from about 2 GPT to about 2.5 GPT, an amount ranging from about2.5 GPT to about 3 GPT, an amount ranging from about 3 GPT to about 3.5GPT, an amount ranging from about 3.5 GPT to about 4 GPT, oralternatively, an amount ranging between any of the previously recitedranges. When provided as a liquid additive, the friction reducingpolymer may be in the form of an emulsion, a liquid concentrate, orboth. One of ordinary skill will understand that a volume ratio such asGPT is equivalent to a volume ratio using a different basis such asliters or cubic meters. Additionally, the friction reducing polymer maybe provided as a dry additive and may be present in an amount rangingfrom about 0.01% wt. % to about 0.5 wt. % or more based on a totalweight of the hydraulic fracturing fluid. Alternatively an amountranging from about 0.01 wt. % to about 0.025 wt. %, an amount rangingfrom about 0.025 wt. % to about to about 0.04 wt. %, an amount rangingfrom about 0.04 wt. % to about 0.06 wt. %, an amount ranging from about0.06 wt. % to about 0.09 wt. %, an amount ranging from about 0.09 wt. %to about 0.12 wt. %, an amount ranging from about 0.12 wt. % to about0.15 wt. %, an amount ranging from about 0.15 wt. % to about 0.2 wt. %,an amount ranging from about 0.2 wt. % to about 0.25 wt. %, an amountranging from about 0.25 wt. % to about 0.3 wt. %, an amount ranging fromabout 0.3 wt. % to about 0.35 wt. %, an amount ranging from about 0.35wt. % to about 0.4 wt. %, an amount ranging from about 0.45 wt. % toabout 0.5 wt. %, or alternatively, an amount ranging between any of thepreviously recited ranges.

Gelling agents may be included in the hydraulic fracturing fluid toincrease the hydraulic fracturing fluid's viscosity which may be desiredfor some types of subterranean applications. For example, an increase inviscosity may be used for transferring hydraulic pressure to diverttreatment fluids to another part of a formation or for preventingundesired leak-off of fluids into a formation from the buildup of filtercakes. The increased viscosity of the gelled or gelled and cross-linkedtreatment fluid, among other things, may reduce fluid loss and may allowthe fracturing fluid to transport significant quantities of suspendedproppant. Gelling agents may include, but are not limited to, anysuitable hydratable polymer, including, but not limited to,galactomannan gums, cellulose derivatives, combinations thereof,derivatives thereof, and the like. Galactomannan gums are generallycharacterized as having a linear mannan backbone with various amounts ofgalactose units attached thereto. Examples of suitable galactomannangums include, but are not limited to, gum arabic, gum ghatti, gumkaraya, tamarind gum, tragacanth gum, guar gum, locust bean gum,combinations thereof, derivatives thereof, and the like. Other suitablegums include, but are not limited to, hydroxyethylguar,hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar andcarboxymethylhydroxypropylguar. Examples of suitable cellulosederivatives include hydroxyethyl cellulose, carboxyethylcellulose,carboxymethylcellulose, and carboxymethylhydroxyethylcellulose;derivatives thereof, and combinations thereof. The crosslinkablepolymers included in the treatment fluids of the present disclosure maybe naturally-occurring, synthetic, or a combination thereof. Thecrosslinkable polymers may include hydratable polymers that contain oneor more functional groups such as hydroxyl, cis-hydroxyl, carboxyl,sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups. Incertain systems and/or methods, the crosslinkable polymers may be atleast partially crosslinked, wherein at least a portion of the moleculesof the crosslinkable polymers are crosslinked by a reaction including acrosslinking agent. The gelling agent may be present in the fracturingfluid in an amount ranging from about 0.5 lbs/1,000 gal of hydraulicfracturing fluid (0.05991 kg/m{circumflex over ( )}3) to about 200lbs/1,000 gal (23.946 kg/m{circumflex over ( )}3). Alternatively, in anamount ranging from about 5 lbs/1,000 gal (0.5991 kg/m{circumflex over( )}3) to about 10 lbs/1,000 gal (1.198 kg/m{circumflex over ( )}3), inan amount ranging from about 10 lbs/1,000 gal (1.198 kg/m{circumflexover ( )}3) to about 15 lb/1,000 gal (1.797 kg/m{circumflex over ( )}3),in an amount ranging from about 15 lb/1,000 gal (1.797 kg/m{circumflexover ( )}3) to about 20 lb/1,000 gal (2.3946 kg/m{circumflex over( )}3), or alternatively, an amount ranging between any of thepreviously recited ranges.

The hydraulic fracturing fluid may include any number of additionaloptional additives, including, but not limited to, salts, acids, fluidloss control additives, gas, foamers, corrosion inhibitors, scaleinhibitors, catalysts, clay control agents, biocides, friction reducingpolymers, iron control agent, antifoam agents, bridging agents,dispersants, hydrogen sulfide (“H₂S”) scavengers, carbon dioxide (“CO₂”)scavengers, oxygen scavengers, lubricants, viscosifiers, breakers,weighting agents, inert solids, emulsifiers, emulsion thinner, emulsionthickener, surfactants, lost circulation additives, pH control additive,buffers, crosslinkers, stabilizers, chelating agents, mutual solvent,oxidizers, reducers, consolidating agent, complexing agent, particulatematerials and any combination thereof. With the benefit of thisdisclosure, one of ordinary skill in the art should be able to recognizeand select a suitable optional additive for use in the fracturing fluid.

FIG. 2 illustrates an example of a well system 104 that may be used tointroduce proppant 116 into fractures 100. Well system 104 may include afluid handling system 106, which may include fluid supply 108, mixingequipment 109, pumping equipment 110, and wellbore supply conduit 112.Pumping equipment 110 may be fluidly coupled with the fluid supply 108and wellbore supply conduit 112 to communicate a fracturing fluid 117,which may include proppant 116 into wellbore 114. Proppant 116 may beany of the proppants described herein. The fluid supply 108 and pumpingequipment 110 may be above the surface 118 while the wellbore 114 isbelow the surface 118.

Well system 104 may also be used for the pumping of a pad or pre-padfluid into the subterranean formation at a pumping rate and pressure ator above the fracture gradient of the subterranean formation to createand maintain at least one fracture 100 in subterranean formation 120.The pad or pre-pad fluid may be substantially free of solid particlessuch as proppant, for example, less than 1 wt,% by weight of the pad orpre-pad fluid. Well system 104 may then pump the fracturing fluid 117into subterranean formation 120 surrounding the wellbore 114. Generally,a wellbore 114 may include horizontal, vertical, slanted, curved, andother types of wellbore geometries and orientations, and the proppant116 may generally be applied to subterranean formation 120 surroundingany portion of wellbore 114, including fractures 100. The wellbore 114may include the casing 102 that may be cemented (or otherwise secured)to the wall of the wellbore 114 by cement sheath 122. Perforations 123may allow communication between the wellbore 114 and the subterraneanformation 120. As illustrated, perforations 123 may penetrate casing 102and cement sheath 122 allowing communication between interior of casing102 and fractures 100. A plug 124, which may be any type of plug foroilfield applications (e.g., bridge plug), may be disposed in wellbore114 below the perforations 123.

In accordance with systems and/or methods of the present disclosure, aperforated interval of interest 130 (depth interval of wellbore 114including perforations 123) may be isolated with plug 124. A pad orpre-pad fluid may be pumped into the subterranean formation 120 at apumping rate and pressure at or above the fracture gradient to createand maintain at least one fracture 100 in subterranean formation 120,Then, proppant 116 may be mixed with an aqueous based fluid via mixingequipment 109, thereby forming a fracturing fluid 117, and then may bepumped via pumping equipment 110 from fluid supply 108 down the interiorof casing 102 and into subterranean formation 120 at or above a fracturegradient of the subterranean formation 120. Pumping the fracturing fluid117 at or above the fracture gradient of the subterranean formation 120may create (or enhance) at least one fracture (e.g., fractures 100)extending from the perforations 123 into the subterranean formation 120.Alternatively, the fracturing fluid 117 may be pumped down productiontubing, coiled tubing, or a combination of coiled tubing and annulusbetween the coiled tubing and the casing 102.

At least a portion of the fracturing fluid 117 may enter the fractures100 of subterranean formation 120 surrounding wellbore 114 by way ofperforations 123. Perforations 123 may extend from the interior ofcasing 102, through cement sheath 122, and into subterranean formation120.

Referring to FIG. 3, the wellbore 114 is shown after placement of theproppant 116 in accordance with systems and/or methods of the presentdisclosure. Proppant 116 may be positioned within fractures 100, therebypropping open fractures 100.

The pumping equipment 110 may include a high pressure pump. As usedherein, the term “high pressure pump” refers to a pump that is capableof delivering the fracturing fluid 117 and/or pad/pre-pad fluid downholeat a pressure of about 1000 psi (6894 kPa) or greater. A high pressurepump may be used when it is desired to introduce the fracturing fluid117 and/or pad/pre-pad fluid into subterranean formation 120 at or abovea fracture gradient of the subterranean formation 120, but it may alsobe used in cases where fracturing is not desired. Additionally, the highpressure pump may be capable of fluidly conveying particulate matter,such as the proppant 116, into the subterranean formation 120. Suitablehigh pressure pumps may include, but are not limited to, floating pistonpumps and positive displacement pumps. Without limitation, the initialpumping rates of the pad fluid, pre-pad fluid and/or fracturing fluid117 may range from about 15 barrels per minute (“bbl/min”) (2385 l/min)to about 80 bbl/min (12719 l/min), enough to effectively create afracture into the formation and place the proppant 116 into at least onefracture 101.

Alternatively, the pumping equipment 110 may include a low pressurepump. As used herein, the term “low pressure pump” refers to a pump thatoperates at a pressure of about 1000 psi (6894 kPa) or less. A lowpressure pump may be fluidly coupled to a high pressure pump that may befluidly coupled to a tubular (e.g., wellbore supply conduit 112). Thelow pressure pump may be configured to convey the fracturing fluid 117and/or pad/pre-pad fluid to the high pressure pump. The low pressurepump may “step up” the pressure of the fracturing fluid 117 and/orpad/pre-pad fluid before it reaches the high pressure pump.

Mixing equipment 109 may include a mixing tank that is upstream of thepumping equipment 110 and in which the fracturing fluid 117 may beformulated. The pumping equipment 110 (e.g., a low pressure pump, a highpressure pump, or a combination thereof) may convey fracturing fluid 117from the mixing equipment 109 or other source of the fracturing fluid117 to the casing 102. Alternatively, the fracturing fluid 117 may beformulated offsite and transported to a worksite, in which case thefracturing fluid 117 may be introduced to the casing 102 via the pumpingequipment 110 directly from its shipping container (e.g., a truck, arailcar, a barge, or the like) or from a transport pipeline. In eithercase, the fracturing fluid 117 may be drawn into the pumping equipment110, elevated to an appropriate pressure, and then introduced into thecasing 102 for delivery downhole.

A hydraulic fracturing operation may operate in stages where a bridgeplug, frac plug, or other obstruction is inserted into the wellbore toprevent fluid communication with a region of the wellbore after thebridge plug. A perforating gun including explosive shaped charges may beinserted into a region of the wellbore before the bridge plug (i.e. aregion where the measured depth is less than the measured depth of thebridge plug) and perforate holes through the walls of the wellbore. Theperforating gun may be removed from the wellbore and a fracturing fluidintroduced thereafter. The stage is completed when the planned volume offluid and proppant has been introduced into the subterranean formation.Another stage may begin with the insertion of a second bridge plug intoa wellbore region before the bridge plug.

The exemplary treatment fluids disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed treatment fluids. For example, thedisclosed treatment fluids may directly or indirectly affect one or moremixers, related mixing equipment, mud pits, storage facilities or units,composition separators, heat exchangers, sensors, gauges, pumps,compressors, and the like used generate, store, monitor, regulate,and/or recondition the exemplary treatment fluids. The disclosedtreatment fluids may also directly or indirectly affect any transport ordelivery equipment used to convey the treatment fluids to a well site ordownhole such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to compositionally movethe treatment fluids from one location to another, any pumps,compressors, or motors (e.g., topside or downhole) used to drive thetreatment fluids into motion, any valves or related joints used toregulate the pressure or flow rate of the treatment fluids, and anysensors (i.e., pressure and temperature), gauges, and/or combinationsthereof, and the like. The disclosed treatment fluids may also directlyor indirectly affect the various downhole equipment and tools that maycome into contact with the treatment fluids such as, but not limited to,wellbore casing, wellbore liner, completion string, insert strings,drill string, coiled tubing, slick line, wireline, drill pipe, drillcollars, mud motors, downhole motors and/or pumps, cement pumps,surface-mounted motors and/or pumps, centralizers, turbolizers,scratchers, floats (e.g., shoes, collars, valves, etc.), logging toolsand related telemetry equipment, actuators (e.g., electromechanicaldevices, hydro mechanical devices, etc.), sliding sleeves, productionsleeves, plugs, screens, filters, flow control devices (e.g., inflowcontrol devices, autonomous inflow control devices, outflow controldevices, etc.), couplings (e.g., electro-hydraulic wet connect, dryconnect, inductive coupler, etc.), control lines (e.g., electrical,fiber optic, hydraulic, etc.), surveillance lines, drill bits andreamers, sensors or distributed sensors, downhole heat exchangers,valves and corresponding actuation devices, tool seals, packers, cementplugs, bridge plugs, and other wellbore isolation devices, orcomponents, and the like.

Accordingly, the present disclosure may provide methods relating topreparation of fracturing fluids and to a screening method for frictionreducer precipitation. The methods may include any of the variousfeatures disclosed herein, including one or more of the followingstatements.

Statement 1. A method of preparing a fracturing fluid comprising:preparing or providing an aqueous fluid containing iron ions; screeninga plurality of friction reducers against the aqueous fluid wherein theplurality of friction reducers are anionic, cationic, nonionic,amphoteric, or combinations thereof; selecting at least one frictionreducer from the plurality of friction reducers based at least in parton the step of screening; and preparing a fracturing fluid including theat least one friction reducer.

Statement 2. The method of statement 1 wherein the step of preparing orproviding comprises dissolving an iron containing compound in water orreacting an iron containing compound to release iron ions in water.

Statement 3. The method of any of statements 1-2 wherein the ironcontaining compound is FeCl₂.

Statement 4. The method of any of statements 1-3 wherein the aqueousfluid further comprises at least one ion selected from the groupconsisting of calcium ions, magnesium ions, sodium ions, barium ions,chloride ions, and combinations thereof.

Statement 5. The method of any of statements 1-4 wherein the pluralityof friction reducers comprise at least one of a polyacrylamide, apolyacrylamide derivative, a synthetic polymer, an acrylamide copolymer,an anionic acrylamide copolymer, a cationic acrylamide copolymer, anonionic acrylamide copolymer, an amphoteric acrylamide copolymer, apolyacrylate, a polyacrylate derivative, a polymethacrylate, apolymethacrylate derivative, polymers synthesized from one or moremonomeric units selected from the group consisting of acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, acrylamidotertiary butyl sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonicacid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylicacid, acrylic acid esters, or methacrylic acid esters, theircorresponding salts related salts, their corresponding esters, orcombinations thereof.

Statement 6. The method of any of statements 1-5 wherein the fracturingfluid comprises water, the at least one friction reducer, and aproppant.

Statement 7. The method of statement 6 wherein the water comprises atleast one of surface water, ground water, sea water, or produced water.

Statement 8. The method of any of statements 1-7 further comprisingintroducing the fracturing fluid into a subterranean formation.

Statement 9. A method of preparing a fracturing fluid comprising:preparing a laboratory treatment fluid based at least in part on adiluted treatment fluid model; screening a plurality of frictionreducers against the laboratory treatment fluid; selecting at least onefriction reducer from the plurality of friction reducers based at leastin part on the step of screening; and preparing a fracturing fluidincluding the at least one friction reducer.

Statement 10. The method of statement 9 wherein the diluted treatmentfluid model includes a concentration of dissolved species in a dilutedformation fluid, wherein the dissolved species comprises at least iron.

Statement 11. The method of statement 10 wherein the step of preparing alaboratory treatment fluid comprises dissolving an iron containingcompound in water or reacting an iron containing compound to releaseiron ions in water such that a concentration of iron in the laboratorytreatment fluid in the range of about 50% to about 500% of the dilutedtreatment fluid model.

Statement 12. The method of statement 10 wherein the diluted treatmentfluid model further includes a concentration of at least one ionselected from the group consisting of calcium ions, magnesium ions,sodium ions, barium ions, chloride ions, and combinations thereof.

Statement 13. The method of any of statements 9-12 wherein the step ofpreparing a laboratory treatment fluid comprises dissolving a compoundcontaining at least one of iron ions, calcium ions, magnesium ions,sodium ions, barium ions, chloride ions, and combinations thereof, inwater such that a concentration of ions in the laboratory treatmentfluid in the range of 50% to about 500% of the diluted treatment fluidmodel.

Statement 14. The method of any of statements 9-13 wherein the dilutedtreatment fluid model is based at least in part on measurement of avolume of formation brine and concentration of dissolved species thereinand a volume of treatment fluid and concentration of dissolved speciestherein.

Statement 15. The method of any of statements 9-14 wherein the pluralityof friction reducers comprise at least one of a polyacrylamide, apolyacrylamide derivative, a synthetic polymer, an acrylamide copolymer,an anionic acrylamide copolymer, a cationic acrylamide copolymer, anonionic acrylamide copolymer, an amphoteric acrylamide copolymer, apolyacrylate, a polyacrylate derivative, a polymethacrylate, apolymethacrylate derivative, polymers synthesized from one or moremonomeric units selected from the group consisting of acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, acrylamidotertiary butyl sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonicacid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylicacid, acrylic acid esters, or methacrylic acid esters, theircorresponding salts related salts, their corresponding esters, orcombinations thereof.

Statement 16. The method of any of statements 9-15 wherein thefracturing fluid comprises water, the at least one friction reducer, anda proppant.

Statement 17. The method of any of statements 9-16 further comprisingintroducing the fracturing fluid into a subterranean formation.

Statement 18. A method comprising: preparing a fluid comprising waterand iron ions in an amount greater than 1000 ppm; screening a pluralityof friction reducers against the fluid; selecting at least one frictionreducer from the plurality of friction reducers based at least in parton the step of screening; and preparing a fracturing fluid including theat least one friction reducer.

Statement 19. The method of statement 18 wherein iron ions are presentin an amount at a point in a range of about 1500 ppm to about 2500 ppm.

Statement 20. The method of any of statements 18-19 wherein theplurality of friction reducers comprise at least one of apolyacrylamide, a polyacrylamide derivative, a synthetic polymer, anacrylamide copolymer, an anionic acrylamide copolymer, a cationicacrylamide copolymer, a nonionic acrylamide copolymer, an amphotericacrylamide copolymer, a polyacrylate, a polyacrylate derivative, apolymethacrylate, a polymethacrylate derivative, polymers synthesizedfrom one or more monomeric units selected from the group consisting ofacrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid,acrylamido tertiary butyl sulfonic acid, N,N-dimethylacrylamide, vinylsulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid,methacrylic acid, acrylic acid esters, or methacrylic acid esters, theircorresponding salts related salts, their corresponding esters, orcombinations thereof.

Examples

In the following example, the testing method described above will beillustrated. A test fluid was prepared by dissolving 2000 ppm of Fe2+ions, provided as FeCl2 in 500 ml of tap water. Thereafter, 5 gpt(gallons per thousand gallons) of an anionic acrylamide copolymer-basedfriction reducer with about 40% by weight of dried acrylamide copolymerwas added to the test fluid. Fluffy precipitates quickly formed when theiron ions and anionic acrylamide copolymer were mixed. The solution inthe bottle was placed in 70° C. water bath. After one day, the solutionin the bottle was taken out of the water bath. It was observed thatprecipitates had settled to the bottom of the solution. The solution wasfiltered with filter paper and the precipitates were dried and weighed.19.5 ppt (pounds per thousand gallons) of the dried precipitates wereobtained. FIG. 4 is a photograph of the fluid sample containingprecipitated anionic friction reducer. FIG. 5 is a photograph of theprecipitated anionic friction reducer being filtered by the filterpaper.

In a second example method, 2000 ppm of Fe2+ ions was added to 500 ml oftap water, followed by the addition of 5 gpt of a cationic acrylamidecopolymer-based friction reducer. After one day in the water bath at 70°C., the solution in the bottle was taken out of the bath. No obviousprecipitates were observed at the bottom of the solution. The solutionwas filtered with filter paper, and the filtered precipitates were thendried and weighed. Totally, 10.8 ppt of the dried precipitates wereobtained.

In a third test, 2000 ppm of Fe2+ ions was added to 500 ml of tap water,followed by the addition of 5 gpt of a nonionic acrylamidecopolymer-based friction reducer. No obvious precipitates were observedat the bottom of the solution after one day in the water bath at 70° C.The solution was filtered with filter paper, and the filteredprecipitates were then dried and weighed. Totally, 3.8 ppt of the driedprecipitates were obtained. FIG. 6 is a photograph of two fluid samplescontaining cationic and nonionic friction reducer.

As will be apparent to one of ordinary skill in the art, cationic andnonionic friction reducer generally have a better resistance to cationsincluding the iron ion-inflicted damages than anionic friction reducers.As the test above indicate, the anionic friction reducer produced muchmore precipitates than cationic and nonionic friction reducers. Thissuggests that the proposed screening method is effective in estimatinghow well a friction reducer product can resist the damage from cationslike iron.

The screening method described above can also be used to estimate theappropriate dosage of the treatment agents including the iron treatmentagent. By way of example, suitable iron treatment agents may includeethylenediaminetetraacetic acid (EDTA),N-(2-hydroxyethyl)ethylenediamine-N,N′,N′-triacetic acid (HEDTA),glutamic acid, N,N-diacetic acid (GLDA), nitrilotriacetic acid (NTA),methylglycinediacetic acid (MGDA), and the related salts. Four fluidsamples were prepared with the tap water, 2000 ppm of Fe2+ ions (in theform of FeCl2 or its hydrate), and 5 gpt of an anionic acrylamidecopolymer-based friction reducer. Ethylenediaminetetraacetic acid (EDTA)salt was added to the fluid samples in an amount of 0%, 10%, 25%, and50% molar ratios. The molar ratios indicates the molar ratio of EDTA toiron. 10% dose means that the molar ratio of the EDTA salt to the ironwas 1:10 (or 10%). The samples were heated in 70° C. water bath for 1day, and various degrees of precipitates were observed. The results areillustrated in FIG. 7. It was observed that the EDTA salt at 25% dose ormore, precipitates were mostly invisible. The precipitates were thenfiltered, dried, and weighed, and the quantity of the dried precipitatesis recorded in table 1. Again, with the EDTA salt at 25% dose or more,precipitates were 2.5 ppt (the measurement error was estimated to beabout 1-2 ppt), or mostly eliminated. This quick screening suggests that25% iron removing agent may be sufficient for the elimination of theacrylamide polymer precipitates in this case. In addition to themultiple fluid test, other quick screening tests may include frictionloop tests and viscosity measurements with a viscometer.

TABLE 1 The dried precipitate weight vs. the iron removing agent dosage.EDTA 0% 10% 25% 50% Dried Precipitates (ppt) 19.5 5.7 2.5 2.5

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent embodiments may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, all combinations of each embodiment are contemplated andcovered by the disclosure. Furthermore, no limitations are intended tothe details of construction or design herein shown, other than asdescribed in the claims below. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. It is therefore evident that the particularillustrative embodiments disclosed above may be altered or modified andall such variations are considered within the scope and spirit of thepresent disclosure. If there is any conflict in the usages of a word orterm in this specification and one or more patent(s) or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

What is claimed is:
 1. A method of preparing a fracturing fluidcomprising: preparing a laboratory treatment fluid based at least inpart on a treatment fluid model; screening a plurality of frictionreducers against the laboratory treatment fluid, the screeningcomprising: dissolving at least 2,000 ppm of Fe²⁺ ions into water andadding about 2 gpt to about 5 gpt of a friction reducer; storing thewater for at least about a day and monitoring formation of precipitatesof hydrated friction reducing polymers; filtering the precipitates,drying the precipitates, and weighing the precipitates; selecting atleast one friction reducer from the plurality of friction reducers basedat least in part on the step of screening and the presence ofprecipitate; and preparing a fracturing fluid including the at least onefriction reducer.
 2. The method of claim 1 wherein the diluted treatmentfluid model includes a concentration of dissolved species in a dilutedformation fluid, wherein the dissolved species comprises at least iron.3. The method of claim 2 wherein the step of preparing a laboratorytreatment fluid comprises dissolving an iron containing compound inwater or reacting an iron containing compound to release iron ions inwater.
 4. The method of claim 2 wherein the diluted treatment fluidmodel further includes a concentration of at least one ion selected fromthe group consisting of calcium ions, magnesium ions, sodium ions,barium ions, chloride ions, and combinations thereof.
 5. The method ofclaim 4 wherein the step of preparing a laboratory treatment fluidcomprises dissolving a compound containing at least one of iron ions,calcium ions, magnesium ions, sodium ions, barium ions, chloride ions,and combinations thereof, in water such that a concentration of ions inthe laboratory treatment fluid in the range of 50% to about 500% of thediluted treatment fluid model.
 6. The method of claim 1 wherein thediluted treatment fluid model is based at least in part on measurementof a volume of formation brine and concentration of dissolved speciestherein and a volume of treatment fluid and concentration of dissolvedspecies therein.
 7. The method of claim 1 wherein the plurality offriction reducers comprise at least one of a polyacrylamide, apolyacrylamide derivative, a synthetic polymer, an acrylamide copolymer,an anionic acrylamide copolymer, a cationic acrylamide copolymer, anonionic acrylamide copolymer, an amphoteric acrylamide copolymer, apolyacrylate, a polyacrylate derivative, a polymethacrylate, apolymethacrylate derivative, polymers synthesized from one or moremonomeric units selected from the group consisting of acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, acrylamidotertiary butyl sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonicacid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylicacid, acrylic acid esters, or methacrylic acid esters, theircorresponding salts, their corresponding esters, or combinationsthereof.
 8. The method of claim 1, wherein the fracturing fluidcomprises water, the at least one friction reducer, and a proppant. 9.The method of claim 1, further comprising introducing the fracturingfluid into a subterranean formation.
 10. The method of claim 1, whereinthe friction reducers are in an acid form or a salt form.
 11. The methodof claim 3, wherein the concentration of iron in the laboratorytreatment fluid is in the range of about 50% to about 500% of thediluted treatment fluid model.
 12. The method of claim 1, wherein thediluted treatment fluid model is based at least in part on measurementsmade using open-hole, cased hole, and seismic logging techniques todetermine a volume of formation brine and concentration of dissolvedspecies therein and a volume of treatment fluid and concentration ofdissolved species therein.
 13. The method of claim 1, further comprisingsubjecting the fracturing fluid to a wellbore pressure and a wellboretemperature to simulate a wellbore condition.
 14. The method of claim 8,wherein the water comprises at least one of fresh water, produced water,sea water, ground water, or surface water.
 15. The method of claim 2,wherein the iron containing compound is FeCl₂.
 16. The method of claim5, further comprising subjecting the fracturing fluid to a wellborepressure and a wellbore temperature to simulate a wellbore condition.17. The method of claim 8 wherein the proppant is present at a pointranging from about 0.1 pounds per gallon to about 14 pounds per gallon.